USE OF NANOPARTICLES AS LUBRICITY ADDITIVE IN WELL FLUIDS

Abstract

A use of nanoparticles in a well fluid for improved lubricity is disclosed herein. The nanoparticles are present in the well fluid in low amounts below 5 wt %. The nanoparticles may be formed ex situ and added to the fluid or in situ in the fluid. In one aspect, the well fluid is a drilling fluid. In a further aspect, the well fluid is an invert emulsion based fluid or an aqueous based fluid.

Description

FIELD

The present disclosure relates generally to well fluids with nanoparticles as lubricity additives for improving lubricity, increased rate of penetration, and/or decreasing wellbore friction. In one aspect, the well fluid is drilling fluid used during drilling of underground formations.

BACKGROUND

Friction dissipates energy and causes wear resulting in damage to the equipment. The way to ensure that frictional effects are minimized is through proper lubrication. In carrying out this function, lubricants create a lubricant film on surfaces of moving parts. Lubricant additives can be used in automobiles, lubricants, greases, metal working fluids, oil and gas drilling, heavy machinery and other related industries.

The type of drilling fluids chosen for a given drilling operation depends on the formation being drilled, the depth, the mechanical resistance, and the pressure of the wellbore. Regardless of their type, drilling fluids maintain hole integrity, remove cuttings from the hole, prevent formation damage, suspend cuttings and weighting materials when circulation is stopped, cake off the permeable formation by preventing the passage of fluid into the formation, and cool down and lubricate the drill bit.

Even if a drilling fluid successfully meets all of the above requirements, there is no guarantee that the rate of penetration will be acceptable, since poor lubricity and high friction and drag increase pipe sticking and drilling cycle. The need to overcoming frictional forces is very much encountered during all stages of wells construction; including drilling, completion and maintenance, which originates from the rotation and/or sliding of a pipe inside the well in contact with either the wellbore (metal-to-rock) or the casing (metal-to-metal). These forces hinder directional and extended reach drilling by creating excessive torque and drag. Excessive torque and drag in highly directional and extended-reach wells can exceed the mechanical limits of the drilling equipment, which may expedite wear and tear of down hole tools and equipment and thereby limit production. These problems can be minimized by using drilling fluid with high capabilities of lubricating the different components.

Historically, oil-based products have been used as lubricants for the drilling operations. However, recent environmental regulations limit the usage of aromatic-based oil and require the adaptation of mineral oil, synthetic oil and water based mud where lubricant additives are found useful to increase the lubricity (Riley et al., 2012; Kercheville et al. 1986). In these instances, lubrication is achieved using additives such as liquid lubricants, including glycols, oils, esters, fatty acid esters, surfactants and polymer-based lubricants; and solid lubricants, such as graphite, calcium carbonate flakes, glass and plastic beads (Hoskins, 2010; Skalle et al., 1999). The main function of these additives is to lubricate the drill string and prevent differential sticking. But these available lubricants have not proven entirely effective and suffer from different disadvantages. Both liquid and large sized solid lubricants can cause permanent damage to the formation (Hoskins, 2010; Skalle et al., 1999; Lammons, 1984). Furthermore, micro and macro sized solid lubricants can interfere with drilling equipment and hinder production. The abrasive nature of macro and/or micro sized solid lubricants may cause higher kinetic energy and accelerate or aggravate the wear and tear of the downhole equipment (Amanullah et al., 2011). Some of these solids, nevertheless, get filtered out in the solids control equipment due to their large size and are, therefore, less problematic. Liquid lubricants can also negatively impact the physical and chemical properties of the drilling fluid and lead to foaming (Hoskins, 2010). To counter foaming, costly defoamers must be added to the system. Liquid lubricants form a film between two surfaces and, hence, minimize frequent contact and consequently friction. However, their efficiency largely depends on mud type and may depreciate in the presence of other types of mud additives. It should also be noted that the efficiency of liquid lubricants is entirely lost in high-solids muds. Solid lubricants, on the other hand, do not depreciate as much in such muds (Hoskins, 2010; Skalle et al., 1999). However, these materials are not sufficiently effective to serve their primary goals of reducing the coefficient of friction.

By virtue of their very small sizes, nanoparticles (NPs) have the potential of acting as effective lubricant additives. Their size and shape enable them to enter contact zones between surfaces easily. Inorganic nanoparticles mostly do not display any affinity to oil and may not be affected by the mud type. In-situ and ex-situ techniques for forming a wide variety of well dispersed NPs in an invert emulsion as well as water-based drilling fluid have been detailed in the art (Husein et al., 2012). These methods rely heavily on high shearing, which produces finely dispersed water pools, in the case of invert emulsion drilling fluids, and the use of these water pools as nanoreactors to form NPs with sizes mainly below 100 nm. Once formed, these NPs display very high stability in the mother drilling fluid and interact very effectively with the rest of the drilling fluid (Husein et al., 2012). Previous experiments showed that these particles perfectly seal filter cakes by creating crack-free, very smooth surfaces (Husein et al., 2012). Therefore, these particles contribute to the formation of slippery layers between the borehole and the drill string leading to lower overall friction coefficient and, subsequently, increase the extended reach of horizontal drilling. Moreover, due to the small sizes of these particles, the wear and tear of down hole equipment and tools becomes negligible as less kinetic energy (nano sized particles achieve lower sedimentation speed compare to the large sized particles) and abrasive action is encountered. Overall, the application of nanoparticles in drilling fluid presents a good potential for reducing friction while drilling and, hence, improve the extended reach.

Nanoparticles and nano-emulsion particularly have previously been used in drilling fluids and hydrocarbons for a variety of purposes.

U.S. Patent 20080234149 A1 (2008) is directed to a nanoparticles-based lubricant composed of solid lubricant nano-material (material selected from molybdenum disulphide, tungsten disulphide, gold, silver, lead and tin) having a size less than or equal to 500 nm and a second material which is a chemical surface active agent placed on an external surface of the nanoparticles to minimize particles agglomeration. The nanoparticle preparation protocol is not straight forward and involves many steps, which makes the approach commercially unattractive. This patent does not describe the use of the product particles in drilling fluids, and does not refer to the use of ferric hydroxide and calcium carbonate nanoparticles.

U.S. Pat. No. 6,710,020 (2004) discloses the application of hollow-inorganic fullerene (IF) nanoparticles as a lubricating additive for automotive transport applications. IF nanoparticles having diameters between 10 and 200 nm are slowly released to the surface from its base metal to provide lubrication. These nano-materials are synthesized in a fluidized bed reactor at 850° C. and require different cleaning and purification steps before they could be used. This technique of nanoparticle preparation produces particles with high surface activity, which tends to bind the particles together and limits the quantity of nanoparticles produced. This patent does not include measurements of friction coefficient of drilling fluids.

U.S. Patent 2011/162845 discloses a method of servicing a wellbore. It introduces a lost circulation composition into a lost circulation zone to reduce the loss of fluid into the formation. The lost circulation composition comprises Portland cement in an amount of about 10 wt % to about 20 wt % of the lost circulation composition, 1 to 100 nm nano-silica of 0.5 wt % to 4 wt %, 5 wt % to 10 wt % amorphous silica, 0.5 wt % to 2 wt % synthetic clay, 15 wt % to 50 wt % sub-micron sized calcium carbonate and 60 wt % to 75 wt % water. The lost circulation compositions rapidly developed static gel strength and remained pumpable for at least about 1 day. The sample was observed to gel while static but returned to liquid upon application of shear. This patent only shows the effectiveness in terms of lost circulation control by nano-materials and does not provide any data on friction coefficient of the drilling fluid.

U.S. Patent Application 2009/82230 (2009) relates to an aqueous-based well treatment fluid, including drilling fluids, containing a viscosifying additive. The additive has calcium carbonate nanoparticles with a median particle size of less than or equal to 1 μm. The amount of calcium carbonate nanoparticles used in the drilling fluid is approximately 20 wt %. The nanoparticles used in the well treatment fluid were capable of being suspended in the fluid without the aid of a polymeric viscosifying agent. The addition of nanoparticles altered the viscosity of the fluid. Nanoparticles suspended in a well treatment fluid exhibited sagging (inadequate suspension properties) particularly at high temperatures of around 350° F. The viscosity changes of a fluid upon addition of nanoparticles were well reported. However, even with the high amount of nanoparticles added to the fluid formulation, no fluid loss and lubricity data were reported.

U.S. Pat. No. 8,071,510 (2011) is directed to a method of increasing the lubricity or reducing the coefficient of friction of a drilling or completion fluid by using brine of at least one water soluble salt, vegetable oil and an anionic or non-ionic surfactant in order to assist in the solubilization of the salt. This patent does not describe the use of the nanoparticles for reducing the coefficient of friction. Further, the present inventors have found that sodium salts have a negative impact on lubricity quality, as set out below.

Yang et al. (2012) developed a nanoscale emulsion lubricating material to solve the high friction drag in drilling operation. It increased lubricity by 50 wt %, but did not improve fluid loss and viscosity property. Their work did not involve nanoparticles.

Riley et al. (2012) studied the addition of silica-based nanoparticles in drilling fluid and reported 20% lower coefficient of friction upon applying 150 lb/lbs of torque.

Other references, such as Amanullah et al. 2011, consider the use of small amounts of nanoparticles in water and indicate the potential for beneficial effects on differential sticking, torque reduction and reduction of drag problems in certain types of drilling. However, these references experiment with nanoparticles in water and require very active stabilizers to maintain the nanoparticle dispersions or look at the interaction of nanoparticles with other components that may be present in a well fluid. The references do not provide data directly relevant to lubricity results in industrial drilling fluids but merely indicate further areas for research.

It is, therefore, desirable to provide an improved drilling fluid having a decreased coefficient of friction.

SUMMARY

It is an object of the present disclosure to obviate or mitigate at least one disadvantage of previous fluids.

The present disclosure is directed to nanoparticles for use in well fluids, and in one aspect, drilling fluids, as a lubricity additive to reduce friction and increase lubricity. The lubricity additive will reduce the co-efficient of friction at a given torque.

In one aspect, the nanoparticles are hydroxide, and/or carbonate nanoparticles. The nanoparticles are present in the fluid in low amounts. The nanoparticles are present in amounts of less than 5 wt %, and may be present in amounts between 0.1 wt % and 4 wt %, and in a further aspect between 1 wt % and 4 wt %. As a result, the nanoparticles do not significantly alter the other characteristics of the fluid.

In one aspect, the nanoparticles useful as a lubricity additive are formed ex situ and added to the well fluid or formed in situ in the fluid.

In a further aspect, the nanoparticles are formed ex situ, by providing aqueous-based precursor solutions for forming the nanoparticles, mixing the precursor solutions under high shear, and adding the mixed product suspension to the well fluid under high shear to form the nanoparticle-containing well fluid, wherein the nanoparticles act as a lubricity additive.

In a further aspect, the nanoparticles are formed in situ, by providing aqueous-based precursor solutions for forming the nanoparticles, adding the precursor solutions successively to the well fluid, and subjecting the fluid to mixing and shearing to form the nanoparticles in the fluid, wherein the nanoparticles act as lubricity additive.

In another aspect, the nanoparticles are formed in situ, comprising the steps of providing the solid precursor for forming the nanoparticles, adding the precursors successively or simultaneously to the well fluid, and subjecting the fluid to mixing and shearing to form the nanoparticles in the fluid, wherein the nanoparticles act as lubricity additive.

Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific aspects in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Aspects of the present disclosure will now be described, by way of example only, with reference to the attached Figures.

FIG. 1 is a schematic diagram of the procedure used to make the nanoparticles ex situ.

FIG. 2 is a schematic diagram of the procedure used to make the nanoparticles in situ.

FIG. 3 is a schematic diagram of a further procedure used to make the nanoparticles in situ.

DETAILED DESCRIPTION

Generally, the present disclosure provides a use of nanoparticles as a lubricity additive in a well fluid, and, in one aspect, in a drilling fluid. The lubricity additive reduces the friction and increases lubricity.

The nanoparticle-containing fluids have one or more of the following advantages. The nanoparticles act as a lubricity additive to reduce the coefficient of friction as compared to fluids without the nanoparticles. The nanoparticles form a thin, slippery and firm filter cake in the formation which can help reduce fluid loss that causes minimal formation damage. They result in less torque and drag. Also, particles that are embedded in the wall cake provide a load-bearing surface between pipe and therefore increasing extended reach wells, deviated and horizontal drilling. Nanoparticles will also pass the solids control equipment unspoiled. They are stable at extremely high temperatures. The nanoparticles are present in the fluids at low concentrations and may be used without other lubricant materials. The low concentration results in less formation damage, no significant change to the characteristic of the fluid and an increase in productivity index. The nanoparticles can be formed ex situ and added to the fluid or formed in situ in the fluid. This results in time and cost savings.

The well fluid can be any fluid that is pumped in pipes or flows through a formation. Any such fluid needs to display low friction, otherwise pumping costs will be significant. In particular, the well fluid is a kill fluid, completion fluid, pre-stimulation fluid or drilling fluid. In one aspect, it is a drilling fluid. Although this disclosure describes the fluid as a drilling fluid, a skilled person will understand that the nanoparticles may be used as a lubricity additive in any well fluid.

In one aspect, the well fluids are aqueous-based or invert emulsion fluids. Hydrocarbon based emulsions contain a large amount, i.e. 95 vol %, hydrocarbon based material (oil) as the continuous phase of the emulsion. The remainder of the emulsion is a minor amount of an aqueous phase as the discontinuous phase of the emulsion.

The well fluids, and in one aspect drilling fluids, may contain a number of common additives such as weighting agents, emulsifiers, surfactants, foaming agents, surfactants, etc. The nanoparticles and their concentrations are selected such that they do not affect the other characteristics of the fluid.

In one aspect, the nanoparticles are selected from metal hydroxides, e.g. iron hydroxide, metal carbonates, e.g. calcium carbonate. These particles may act as lost circulation material in addition to lubricity additive.

The synthesis of the nanoparticles (NPs) additive is a chemo-mechanical process. The unique process enables finely disperse NPs formation in the water-in-oil based fluids (invert emulsion fluids) as well as water-based fluids. As a result, the NPs can be easily inserted into the current lubricant system. The severity of the drilling process, nevertheless, may induce particle agglomeration. However, the surfactants existing in drilling fluid would act as stabilizers and would limit agglomeration through steric hindrance. In one aspect, the nanoparticles have a particle size in the range of 1 to 120 nm and in a further aspect the majority or most of the nanoparticles have a particle size in the range of 1 to 30 nm. In a further aspect, substantially all of the nanoparticles have a particle size is the range of 1 to 30 nm.

Nanoparticles based lubricant additive is prepared through a proprietary manufacturing process according to Zakaria et al. (2012) and Husein et al. (2012).

Lubricants play an important role in reducing friction and wear and preventing component failure. Economically affordable nanoparticles are combined with the invert emulsion well fluids or water-based well fluids to achieve the desired lubricity property. Characterization of the nanoparticles is accomplished through powder X-ray diffraction patterns (XRD), energy dispersive X-ray (EDX), scanning electron microscopy (SEM) and transmission electron microscopy (TEM). The results for drilling fluids are disclosed in PCT/CA2012/50075 (Husein et al., 2012). NPs are able to stop the intrusion of fluid into the formation as well as increase the lubricity during drilling.

NP-based lubricants are nanosized solid particles, which are chemically and physically stable. Under the conditions of load and temperature resulting from the contacting surfaces, these NPs furnish a thin film of lubricant layer on the contacting surfaces leading to reduced friction between the surfaces. The lubrication effect is influenced by the hydrodynamic properties of the fluid and the size of the NPs.

The drilling fluid transports the solid lubricant NPs to the contacting surfaces.

In a further aspect of the disclosure, the nanoparticles in the fluid can be made using either in situ or ex situ techniques. The in situ technique is preferred.

The NPs can be formed in situ in the well fluid. This eliminates the handling and agglomeration problems present with many commercial prepared nanoparticles. In this method, aqueous precursors of the NPs are added to the well fluid and mixed thoroughly. High shear is applied to the well fluid to ensure intimate mixing for the formation of stable ultradispersed NPs in the well fluid. The stability of the resultant NPs hinges upon particle size.

In another aspect, the in situ NPs are prepared by directly adding the solid precursors into the well fluid coupled with intensive mixing and shearing. One needs to ensure that the volume and chemical composition of the innate water in the well fluid allows for complete dissolution of the precursors.

In the ex situ process, the NPs are pre-prepared from their precursors. Precursors, in one aspect aqueous precursor solutions, are mixed under high shearing. The resultant NPs are then added to the well fluid under high mixing and shearing.

The mixing and shearing needed for NPs formation may easily be made available on an oil rig. Special in-line mixers or shearing available from the high pressure pump should provide the needed mixing. Experimental results showed that 1 wt % of Fe(OH)₃ or 4 wt % of CaCO₃ NPs induce appreciable reduction in the coefficient of friction. Moreover, at the level of NPs added, no impact on drilling fluid specific gravity, apparent viscosity and pH was observed.

1. DRILLING FLUID SAMPLES

The invert emulsion was supplied by a Calgary based drilling fluid company. One mix of the drilling fluid namely, 90 oil: 10 water (V/V) was tested. The composition of the invert emulsion drilling fluid is shown in Table 1.

TABLE 1
Compositions of drilling fluid samples
Oil:water (V/V) = 90:10
Base Oil = Low-aromatic hydrotreated oil
Brine = 30% Calcium Chloride
Organophillic Clays = 15 kg/m3
Hot Lime = 35 kg/m3
Primary Emulsifier = 10 L/m3
Secondary Emulsifier = 5 L/m3

The NP concentration was maintained at 1 wt % and 4 wt % for the in situ and ex situ prepared Fe(OH)₃ and CaCO₃ particles, respectively.

2. PREPARATION OF IRON (III) HYDROXIDE AND CALCIUM CARBONATE NPS AND THE NP-BASED DRILLING FLUID IRON (III) HYDROXIDE NPS

Iron (III) hydroxide NPs were prepared by aqueous reaction between FeCl₃ and NaOH at specified temperature and rate of mixing as per the following reaction.

FeCl_3(aq)+3NaOH_(aq)→Fe(OH)_3(s)+3NaCl_(aq)   (R1)

Ex situ preparation: Iron hydroxide NPs were prepared by first solubilizing specific amount of anhydrous iron (III) chloride powder (laboratory grade, Fisher Scientific Company, Toronto, ON, Canada) in 2 mL deionized water to give final concentration of 2.5 M followed by addition of a stoichiometric amount of NaOH_(s) pellets (Fisher Scientific Company, Toronto, ON, Canada) under 200 rpm of mixing and 25° C. The color of the aqueous solution turned reddish brown signaling the formation of precipitate of Fe(OH)_3(s).

The particles were mixed with the invert emulsion drilling fluid in a slurry form. The fluids were mixed/highly sheared to achieve a homogenous mixture using Hamilton beach mixer. FIG. 1 shows a schematic drawing of the experimental procedure.

In situ preparation: This scheme of nanoparticle synthesis followed the two microemulsion method for nanoparticle synthesis (Husein and Nassar, 2008). A 1 mL of 5 M FeCl_3(aq) was added to 250 mL of the drilling fluid, and in a separate vial 1 mL of 16 M NaOH_(aq) was added to 250 mL of the drilling fluid. The two vials were mixed overnight at 200 rpm and 25° C. Two control samples were prepared one containing the FeCl_3(aq) in the drilling fluid and another containing the NaOH_(aq) in the drilling fluid and the samples were left to mix overnight at 200 rpm and 25° C. Finally to achieve a homogenous mixture of the fluid samples and disperse the NPs more effectively, Hamilton beach mixer was used. FIG. 2 shows a schematic drawing of the experimental procedure.

In another aspect, in situ NPs were prepared by adding the solid precursors of FeCl₃ and NaOH at the stoichiometric ratio in small batches directly into the drilling fluid under high mixing and shearing. The water pools of the invert emulsion solubilize the solid precursors, and once solubilized, precursors react to form the solid product. The size of the Fe(OH)₃ product remains in the nano domain by virtue of the limited size of the water pool, which, in turn, is preserved by the surrounding layer of surfactant molecules. FIG. 3 is a schematic representation of the process.

Calcium Carbonate Nanoparticles:

Calcium Carbonate NPs were prepared by aqueous reaction between Ca(NO₃)₂ and Na₂CO₃ at specified temperature and rate of mixing as per the following reaction (R2).

Ca(NO₃)_2(aq)+Na₂CO_3(aq)→CaCO_3(s)+2 NaNO_3(aq)   (R2)

Ex situ preparation: Calcium carbonate NPs were prepared by first solubilizing specific amount of anhydrous sodium carbonate powder in 5 mL deionized water to give a final concentration of 2.26 M followed by addition of 1 mL of 7.6 M stoichiometric amount of aqueous calcium nitrate under 200 rpm of mixing at 25° C. The color of the aqueous solution turned white signaling the formation of precipitate of CaCO_3(s) as per reaction (R2). FIG. 1 shows a schematic drawing of the experimental procedure. The product NP-slurry was mixed with the drilling fluid under high mixing and shearing using Hamilton beach mixer.

In situ preparation: A 5 mL of 2.2 M sodium carbonate was added to 250 mL of the drilling fluid and in a separate vial 1 mL of 7.6 M aqueous calcium nitrate was added to 250 mL of the drilling fluid. The samples were left to mix overnight at 200 rpm and 25° C. Finally to achieve a homogenous mixture of the fluid samples and disperse the NPs more effectively, Hamilton beach mixer was used. FIG. 2 shows a schematic drawing of the experimental procedure.

3. LUBRICITY TESTING METHOD

A functional (drilling fluid lubricity) test was designed to simulate the torque and drag produced by a given drilling fluid.

The lubricity test was designed to simulate the speed of rotation of the drill pipe and the pressure the pipe bears against the wall of the bore hole (OFITE lubricity test manual, 2011). It also predicts the wear rates of mechanical parts in known fluid systems. Lubricity property of the drilling fluid with NPs was evaluated by OFITE Lubricity Tester (Part no: 111-00, serial: 07-09, Houston, Tex.) at 150 inch-pounds of torque which were applied to two hardened steel surfaces, a block and ring rotating at 60 rpm rotational speed. The test sample was completely immersed between the ring and block. The apparatus ran for 5 min in order to coat the metal test pieces with the sample fluid. The torque adjustment handle was then turned until 150 inch-pounds of torque had been applied to the test block. The machine again ran a 5 min stabilization period. A friction coefficient reading was then taken. Additional readings were taken every 5 min until three consecutive readings agreed within ±2 units. The experiments involved three replicates and the 95% confidence interval in Table 2 and Table 3 show high reproducibility of the test results.

The drilling fluid lubricity coefficient can be calculated using the following equation as given in the Ofite manual (Ofite lubricity tester manual, 2011):

$\begin{array}{cc}\mathrm{Coefficient}\mathrm{of}\mathrm{friction}=\frac{\mathrm{lb}\mathrm{force}\mathrm{to}\mathrm{turn}\mathrm{the}\mathrm{ring}}{\mathrm{lb}\mathrm{torque}\mathrm{load}\mathrm{applied}}=\frac{\mathrm{Meter}\mathrm{Reading}}{100}& \left(\mathrm{E1}\right)\end{array}$

Coefficient of Friction (CoF) is used to quantify how readily two surfaces slide in the presence of a lubricant or oil. It is a key factor which directly affects the torque and drag. The lower the value of the coefficient of friction, the higher the lubricity or vice-versa.

The torque reduction, at a given load, can be calculated using the following equation:

$\begin{array}{cc}\mathrm{Percent}\mathrm{torque}\mathrm{reduction}\mathrm{at}\mathrm{given}\mathrm{load}=\frac{\left(A_L-B_L\right)}{A_1}\times 100\mathrm{Where}A_L=\mathrm{Torque}\mathrm{meter}\mathrm{reading}\mathrm{of}\mathrm{untreated}\mathrm{mud}\left(\mathrm{inch}\text{-}\mathrm{pounds}\right)B_L=\mathrm{Torque}\mathrm{meter}\mathrm{reading}\mathrm{of}\mathrm{treated}\mathrm{mud}\left(\mathrm{inch}\text{-}\mathrm{pounds}\right)& \left(\mathrm{E2}\right)\end{array}$

4. EFFECT OF NPS ON THE COEFFICIENT OF FRICTION

The engineered NPs in drilling fluid reduced coefficient of friction and substantially increased lubricity as shown in Table 2.

TABLE 2
Coefficient of friction and % torque reduction in the
presence and absence of NPs in drilling fluid (DF)
	Coefficient of friction
	DF without		% torque reduction
Nanoparticles (NPs)	NPs	DF with ex-	DF with in-	DF with ex-	DF with in-
& Conc. Used	(control)	situ NPs	situ NPs	situ NPs	situ NPs
Fe(OH)3 (1 wt %)	0.095 ± 0.002	0.081 ± 0.004	0.039 ± 0.002	14.73%	58.94%
CaCO3(4 wt %)	0.095 ± 0.002	0.093 ± 0.002	0.059 ± 0.006	2.1%	37.89%

It appears that in situ prepared NPs disperse better and communicate better with the mother drilling fluid as opposed to the ex situ prepared ones. Therefore, in situ prepared NPs may carry a proportion of the load benefiting the improvement of antiwear property more than NPs prepared ex situ. Thus using tailormade NPs in drilling fluid can reduce coefficient of friction and substantially increase lubricity. Improvement in lubricity reduces energy consumption, which, in turn, increases profitability.

Oil-based drilling fluids have the inherent advantage of significantly lower coefficients of friction (CoF). The typical CoF for an oil-based drilling fluid is 0.10 or less (metal to metal). In comparison, water has a CoF of 0.34 and the CoF of water-base drilling fluids typically ranges between 0.2 and 0.5 (Chang et al., 2011). Comparing between the typical oil based mud and NP-containing mud the friction mechanism is most likely a transfer of NPs to the counterface. This suggests that NPs in the contact zone act like ball bearings in the interface between the two surfaces. The small size allows the particles to penetrate into the surface and van der Waals forces ensure that the particles adhere to the surfaces. Regular lubricants, or oil as continuous phase, in drilling fluid can only form a single oil film whereas NPs in drilling fluid can create an additional ball bearings action leading to better lubrication effect.

Iron (III) hydroxide NPs perform better than calcium carbonate NPs. A few iron oxide magnetite structures produced during the preparation of iron oxide/hydroxide nanoparticles could possibly contribute to higher lubricity once captured in the surface within the drilling fluid. NaCl and NaNO₃ salts form as side products during the iron oxide/hydroxide and calcium carbonate NP-based fluid formulation. According to some literature (Scoggins and Ke, 2011; Ke and Foxenberg, 2010), sodium salts improve fluid lubricity. Table 3 shows that these side products, in fact, increase the coefficient of friction. Therefore, the increase in lubricity observed when iron-based and calcium-based NP-drilling fluids are used can be entirely attributed to the nanoparticles.

TABLE 3
Coefficient of friction and % torque reduction in the
presence and absence of salts in drilling fluid (DF)
Salt & Conc.	Coefficient of friction	% torque
Used	DF without salt (control)	DF with salt	reduction
NaCl (1 wt %)	0.0980 ± 0.002	0.100 ± 0.004	−2%
NaNO3(1 wt %)	0.0980 ± 0.002	0.110 ± 0.005	−12%

Nanosized particles are much more readily dispersible than micron-sized ones (Canter, 2009). When dispersed in a drilling fluid, minimum agglomeration and settling occur and a stable suspension form. The stable dispersion is also supported by the presence of surfactant molecules. Both in situ and ex situ prepared nanoparticles are so small in size that a stable colloidal dispersion in drilling fluids can be achieved which probably avoids the undesired precipitation caused by gravitation. With the formation of a stable well-proportioned dispersion, NPs are more prone to be trapped in the rubbing surface due to its excessive surface energy. Dispersed nanoparticles are deposited on the friction surface and sheared off nanoparticles trapped at the interface. Roughness of the surface may be reduced by the polishing effect (Wu et al, 2007; Mosleh et al., 2009). Moreover, the nanoparticles tend to be dispersed uniformly which would result in a more uniform contact stress between the contacting surfaces (Chang and Friedrich, 2010). Moshkovith et al. (2007) studied the lubricity properties of IF-WS₂ and also found dispersion impacts the lubricity performance as the dispersed NPs possess solid lubrication properties due to its stability. It was also found that aggregates size of NPs depend on the mixing time of dispersion. The NPs are engineered to have specific size ranges and shapes so that they can find their way into intricate spaces and maintain lamellar structure. It is therefore speculated that the coefficient of friction reduction is due to the surface boundary films provided by NPs that slide easily over one another like ball bearings. Similar findings have been reported in the literature on the effect of dispersing carbon and metallic-based NPs on tribological performance of lubricating oils (Ajay et al., 2008; Abdullah, 2008; Verma et al., 2008; Zhang et al., 2009). Specifically, a reduction in the coefficient of friction by over 25 percent was observed when adding nickel-based NPs to lubricants (Kostic, 2010).

In addition to reducing torque, higher lubricity also lowers the incidence of stuck pipe, which can significantly lower drilling efficiency. Estimation prepared by oil companies showed that stuck pipe while drilling costs more than $250 million each year (Q'Max Technical Bulletin #7). Minimizing friction and the ability to transfer the weight to the bit are very important factors in drilling highly deviated extended reach and horizontal wells. Moreover, reduction in torque in the presence of NPs signifies higher extended reach wells at a given torque and load on bit.

From the aforementioned discussion it can be pointed out that the ability of NPs to increase lubricity depends on the following features:

• • 1. NPs can adsorb physically on any metal surface due to van der Waals forces.
  • 2. The size of the NPs is so small that they can easily enter a macroscopic sliding contact.
  • 3. The lubrication effect can be generated by the chemical nature of the surfactant as described by Yang et al.(2012) and NPs altogether or NPs alone. Dispersed nanoparticles help reduce agglomeration at the interface and hence, improve the co-efficient of friction. Surfactant can be used to improve the dispersion quality and stability.
  • 4. Coefficient of friction is significantly reduced by NPs alone and salts produced as side products from the NPs formation have no impact on lubricity.

The NP additives are multifunctional. NPs-based lubricants can be used in automobile, lubricants, greases, metal working fluid, heavy machinery and other related industries. Standard laboratory tests indicated that NPs lowered both API and HTHP drilling fluid loss values. It can, also, improve the rheological property and lifting capacity. It has strong adsorption ability and can adhere to the wall and the string and thus improve lubricity. Addition of NPs enhances the load-bearing capacity of the lubricants, preserving the surfaces in direct contact and therefore increases the wear resistance.

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Amanullah. M, Al-Arfaj. K. M, and Al-Abdullatif. Z, “Preliminary Test Results of Nano-based Drilling Fluids for Oil and Gas Field Application”, SPE/AIDC 139534, 1-9, (2011)

Canter. N, “Boron nanotechnology-based lubricant additive”, Tribology and lubrication technology, (2009)

Chang. Li, Friedrich. K, “Enhancement effect of nanoparticles on the sliding wear of short fiber-reinforced polymer composites: A critical discussion of wear mechanisms”, Tribology International, 43, 2355-2364, (2010)

Husein. M, Zakaria. M. F, Hareland. G, “Novel nanobased drilling fluids to mitigate fluid loss” PCT Patent Application No: PCT/CA2012/050075, (2012)

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The above-described aspects are intended to be examples only. Alterations, modifications and variations can be effected to the particular example by those of skill in the art without departing from the scope, which is defined solely by the claims appended hereto.

Claims

1-34. (canceled)

35. A method of making a well fluid, the method comprising steps of: forming an emulsion that includes an oil phase and a water phase;preparing a plurality of precursor materials separately from the emulsion, the precursor materials including hydrophilic reagents that are capable of reactingto form nanoparticles upon mixing of the precursor materials,adding the precursor materials to the emulsion; andthereafter mixing to distribute reagents from the plurality of water-based precursor solutions for in-situ reaction within the water phase,the nanoparticles formed by virtue of the in-situ reaction being present in an amount of less than 5% by weight of the well fluid but which are also effective amounts to improve lubricity of the well fluid.

36. The method of claim 35, wherein the step of forming an emulsion includes forming the well fluid as a water-in-oil emulsion where oil is a continuous phase of the emulsion, and the step of adding the plurality of water-based precursor solutions leaves oil as the continuous phase.

37. The method of claim 36, wherein the step of forming an emulsion includes adding a primary emulsifier and a secondary emulsifier to stabilize the emulsion.

38. The method of claim 35, wherein the step of forming an emulsion includes adding a primary emulsifier and a secondary emulsifier to stabilize the emulsion.

39. The method of claim 35, wherein the step of preparing the plurality of precursor materials includes dissolving at least one of the reagents in water prior to the step of adding the precursor materials.

40. The method of claim 35, wherein the step of preparing the plurality of precursor materials includes dissolving all of the reagents in water prior to the step of adding the precursor materials.

41. The method of claim 35, wherein the step of preparing the plurality of precursor materials includes preparing at least one of the reagents as a solid material for direct addition to the well fluid during the step of adding the precursor materials to the emulsion.

42. The method of claim 35, wherein the step of preparing the plurality of precursor materials includes preparing all of the reagents as solid materials for direct addition to the well fluid during the step of adding the precursor materials to the emulsion.

43. The method of claim 35, further including a step of introducing additional materials to formulate the well fluid as a type of drilling fluid.

44. The method of claim 35, further including a step of introducing additional materials as needed to formulate the well fluid as a type of well kill fluid.

45. The method of claim 35, further including a step of introducing additional materials as needed to formulate the well fluid as a type of well completion fluid.

46. The method of claim 35, further including a step of introducing additional materials as needed to formulate well fluid as a type of well pre-stimulation fluid.

47. The method of claim 35, further including a step of introducing hydrophilic clay.

48. The method of claim 35, wherein the water phase utilized in the step of forming the emulsion is a brine.

49. The method of claim 48, wherein the brine is a calcium chloride brine.

50. The method of claim 35, wherein the oil utilized in the step of forming the emulsion is a low aromatic hydrotreated oil.

51. The method of claim 35, wherein the nanoparticles are formed as the reaction products of iron chloride and sodium hydroxide.

52. The method of claim 35, wherein the reagents react to form iron hydroxide nanoparticles.

53. A well fluid made according to the method of claim 35.

54. A well fluid made according to the method of claim 36.

55. A well fluid made according to the method of claim 39.

56. A well fluid made according to the method of claim 41.

57. A well fluid made according to the method of claim 35, the well fluid being formulated as a type of well fluid selected from the group consisting of a well drilling fluid, a well kill fluid, a well pre-stimulation fluid and a well completion fluid.

58. A well fluid made according to the method of claim 49.

59. A well fluid made according to the method of claim 52.